Natural Gas Processing

Natural Gas ProcessingNatural Gas sourcescrude oil wells (associated gas)gas wells condensate wellsCoal bed methaneNon associated gasRaw natural gas contaminantsHeavier gaseous hydrocarbons:

ethane (C2H6)propane (C3H8)normal butane (n-C4H10)isobutane (i-C4H10)pentanes and even higher molecular weight hydrocarbons

Acid gases: carbon dioxide (CO2)hydrogen sulfide (H2S)mercaptans such as methanethiol (CH3SH) and ethanethiol (C2H5SH).

Other gases: nitrogen (N2)helium (He).

Raw natural gas contaminantsWater: water vaporliquid water. (dissolved salts and dissolved gases)

Liquid hydrocarbonsnatural gas condensate (also referred to as casinghead gasoline or natural gasoline)

Mercury: very small amounts of mercury primarily in elemental form, but chlorides and other species are possibly present.

Radioactive gas: radon. Also, when radon is present, decay products of radon, such as polonium, can accumulate in specific locations within processing equipment.

Pipe line gas caloric value: 1035 5% BTU per cubic foot of gas at 1 atmosphere and 60 degrees Fahrenheit At or above a specified hydrocarbon dew point temperaturefree of particulate solids and liquid water to prevent erosion, corrosion or other damage to the pipeline.dehydrated of water vapor sufficiently to prevent the formation of methane hydrates (less than seven pounds of water per million cubic feet (MMCFD) of gas) Traces of components such as hydrogen sulfide, carbon dioxide, mercaptans, and nitrogen. The most common specification for hydrogen sulfide content is 0.25 grain H2S per 100 cubic feet of gas, or approximately 4 ppm. Specifications for CO2 typically limit the content to no more than two or three percent. Maintain mercury at less than detectable limits (approximately 0.001 ppb by volume)

Condensate is also called natural gasoline or casinghead gasoline."Pentanes +" refers to pentanes and heavier hydrocarbons, and are also called natural gasoline."Acid gases" are hydrogen sulfide and carbon dioxide.PSA is Pressure Swing Adsorption.NGL is Natural Gas Liquids.Sweetening processes remove mercaptans from the NGL products.6Condensate StabilizationHydrocarbon condensate recovered from natural gas may be shipped without further processing; however, frequently it is stabilized for blending into the crude oil stream and thereby sold as crude oil. The process of increasing the amount of intermediates (C3 to C5) and heavy (C+6 ) components in the condensate is called condensate stabilization. This process is performed primarily in order to reduce the vapor pressure of the condensate liquids so that a vapor phase is not produced upon flashing the liquid to atmospheric storage tanks. In other word, the scope of this process is to separate the very light hydrocarbon gases, methane and ethane in particular, from the heavier hydrocarbon components (C+3). Stabilized liquid, however, generally has a vapor pressure specification because the product will be injected into a pipeline or transport pressure vessel, which has definite pressure limitations. Condensates may contain a relatively high percentage of intermediate components and can be separated easily from entrained water due to its lower viscosity and greater density difference with water. Thus, some sort of condensate stabilization should be considered for each gas well production facility. Condensate Stabilization Processes: Stabilization of condensate streams can be carried out using the following two methods:Flash VaporizationFractionation

Flash Vaporization Stabilization by flash vaporization is a simple operation employing only two or three flash tanks. This process is similar to stage separation utilizing the equilibrium principles between vapor and condensate phases. Equilibrium vaporization occurs when the vapor and condensate phases are in equilibrium at the temperature and pressure of separation. Figure 1 shows a typical scheme of condensate stabilization through the flash vaporization process. As shown, condensate from the inlet separator after passing through the exchanger enters to the high-pressure flash tank, where the pressure is maintained at 600 psia. A pressure drop of 300 psia is obtained here, which assists flashing of large amounts of lighter ends, which join the sour vapor stream after recompression. The vapor can either be processed further and put into the sales gas or be recycled into the reservoir and used as gas lift to produce more crude oils. The bottom liquid from the high-pressure tank flows to the middle pressure flash tank operated at 300 psia. Additional methane and ethane are released in this tank. The bottom product is withdrawn again to the low-pressure tank operated at 65 psia. To ensure efficient separation, condensate is degassed in the stripper vessel at the lowest possible pressure prior to storage. This reduces excess flashing of condensate in the storage tank and reduces the inert gas blanket pressure required in it. Note that flash vaporization as a condensate stabilization method is old technology and is not used in a modern gas plant. However, variations of flash technology might also be found on oil production facilities stabilizing crude oil.

Figure 1: Schematic of condensation stabilization unitFractionationStabilization by fractionation is a popular process in the industry and precise enough to produce liquids of suitable vapor pressure. During the operation, light fractions such as methaneethanepropane and most of the butanes are removed and recovered. The finished product from the bottom of the column is composed mainly of pentanes and heavier hydrocarbons, with small amounts of butane. The process actually makes a cut between the lightest liquid component (pentane) and the heaviest gas (butane). The bottom product is thus a liquid free of all gaseous components able to be stored safely at atmospheric pressure.

Stabilization by fractionation is a modern operation and economically attractive next to flash vaporization. It is a single tower process, as only one specification product is required. The bottom product of the column is capable of meeting any kind of rigid specifications with the proper operating conditions.Process DescriptionFigure 2 shows a schematic condensate stabilization process. The liquid hydrocarbon (condensate) is brought into the system from the inlet separator and preheated in the stabilizer feed exchanger before entering the stabilizer feed drum. Liquid from the feed drum is fed to the stabilization tower at approximately 50 to 200 psi. Sometimes the liquid is flashed down to a feed drum at pressure slightly above the tower pressure. This flashes off vapor so that the stabilization tower can often be a smaller diameter.

The condensate stabilizer reduces vapor pressure of the condensate by removing the lighter components. The stabilization is typically carried out in a reboiled column, with tray type internals. However, if a better separation is required, typically the column is changed from a top feed reboiled column to a refluxed distillation tower. As the liquid falls into the column, it becomes leaner in light ends and richer in heavy ends. At the bottom of the tower some of the liquid is circulated through a reboiler to add heat to the tower. As the gas goes up from tray to tray, more and more of the heavy ends get stripped out of the gas at each tray and the gas becomes richer in the light ends and leaner in the heavy ends. Overhead gas from the stabilizer, which would seldom meet market specifications for the natural gas market, is then sent to the low-pressure fuel gas system through a back-pressure control valve that maintains the tower pressure to set point.

Liquids leaving the bottom of the tower have undergone a series of stage flashes at ever-increasing temperatures, driving off the light components, which exit the top of the tower. These liquids must be cooled to a sufficiently low temperature to keep vapors from flashing to atmosphere in the condensate storage tank.

Reboiler Acid Gas TreatingNatural gas contains large amounts of acid gases, such as hydrogen sulfide and carbon dioxide.Sour natural gasNatural gas containing hydrogen sulfide or carbon dioxide is referred to as sour, and Sweet natural gasNatural gas free from hydrogen sulfide is referred to as sweet.

Hydrogen sulfide and carbon dioxide in the presence of water (giving rise to an acidic aqueous solution) and because of the toxicity of hydrogen sulfide and the lack of heating value of carbon dioxide, natural gas being prepared for sales is required to contain no more than 5 ppm hydrogen sulfide and to have a heating value of not less than 920 to 980 Btu/scf. The actual specifications depend on the use and the country where the gas is used. However, because natural gas has a wide range of composition, including the concentration of the two acid gases, processes for the removal of acid gases vary and are subject to choice based on the desired end product.

Several factors should be considered: types and concentrations of contaminants in the gas,the degree of contaminant removal desired, the selectivity of acid gas removal required, the temperature, pressure, volume, and composition of the gas to be processed, the carbon dioxidehydrogen sulfide ratio in the gas, andthe desirability of sulfur recovery due to process economics or environmental issues.In addition to hydrogen sulfide and carbon dioxide, gas may contain other contaminants, such as mercaptans and carbonyl sulfide.

Process selectivity indicates the preference with which the process removes one acid gas component relative to (or in preference to) another. For example, some processes remove both hydrogen sulfide and carbon dioxide; other processes are designed to remove hydrogen sulfide only. It is important to consider the process selectivity, say, hydrogen sulfide removal compared to carbon dioxide removal that ensures minimal concentrations of these components in the product.Acid Gas Removal ProcessesThe processes that have been developed to accomplish gas purification vary from a simple once-through wash operation to complex multistep recycling systems. In many cases, process complexities arise because of the need for recovery of the materials used to remove the contaminants or even recovery of the contaminants in the original, or alteredThere are two general processes used for acid gas removal: AdsorptionAbsorption

Adsorption is a physicalchemical phenomenon in which the gas is concentrated on the surface of a solid or liquid to remove impurities. Usually, carbon is the adsorbing medium, which can be regenerated upon desorption. The quantity of material adsorbed is proportional to the surface area of the solid and, consequently, adsorbents are usually granular solids with a large surface area per unit mass. Subsequently, the captured gas can be desorbed with hot air or steam either for recovery or for thermal destruction. Adsorption is also employed to reduce odors from gases.

There are several limitations to the use of adsorption systems, but it is generally felt that the major one is the requirement for minimization of particulate matter and/or condensation of liquids (e.g., water vapor) that could mask the adsorption surface and reduce its efficiency drastically.

Absorption differs from adsorption in that it is not a physicalchemical surface phenomenon, but a process in which the absorbed gas is ultimately distributed throughout the absorbent (liquid). The process depends only on physical solubility and may include chemical reactions in the liquid phase (chemisorption). Common absorbing media used are water, aqueous amine solutions, caustic, sodium carbonate, and nonvolatile hydrocarbon oils, depending on the type of gas to be absorbed. Usually, the gasliquid contactor designs that are employed are plate columns or packed beds. Absorption is achieved by dissolution (a physical phenomenon) or by reaction (a chemical phenomenon). As currently practiced, acid gas removal processes involve the chemical reaction of the acid gases with a solid oxide (such as iron oxide) or selective absorption of the contaminants into a liquid (such as ethanolamine) that is passed countercurrent to the gas. Then the absorbent is stripped of the gas components (regeneration) and recycled to the absorber. The process design will vary and, in practice, may employ multiple absorption columns and multiple regeneration columns.

Liquid absorption processes [which usually employ temperatures below 50C (120F)] are classified either as physical solvent processes or as chemical solvent processes. The former processes employ an organic solvent, low temperatures, or high pressure. In chemical solvent processes, absorption of the acid gases is achieved mainly by use of alkaline solutions such as amines or carbonates.Regeneration (desorption) can be brought about by the use of reduced pressures and/or high temperatures, whereby the acid gases are stripped from the solvent. Amine washing of natural gas involves chemical reaction of the amine with any acid gases with the liberation of an appreciable amount of heat and it is necessary to compensate for the absorption of heat. Amine derivatives such as ethanolamine (monoethanolamine), diethanolamine, triethanolamine, methyldiethanolamine, diisopropanolamine, and diglycolamine have been used in commercial applications.

Batch Type Processes

The most common type of process for acid gas removal is the batch type process and may involve a chemical process in which the acid gas reacts chemically with the cleaning agent, usually a metal oxide. These processes have the common requirement that the process beoperated as a batch system where, at the end of the cycle, the chemical agent must be changed or regenerated in order to continue treating. Batch processes are limited to removing small amounts of sulfur, i.e., low gas flow rates and/or small concentrations of hydrogen sulfide.

These processes are described in detail as follows.

Metal Oxide Processes

These processes scavenge hydrogen sulfide and organic sulfur compounds (mercaptans) from gas streams through reactions with solid-based media. They are typically nonregenerable, although some are partially regenerable, losing activity upon each regeneration cycle. Most dry sorption processes are governed by the reaction of a metal oxide with H2S to form a metal sulfide compound. For regenerable reactions, the metal sulfide compound can then react with oxygen to produce elemental sulfur and a regenerated metal oxide. The primary metal oxides used for dry sorption processes are iron oxide and zinc oxide.

Dry sorption processes can be categorized into two subgroups: oxidation to sulfur and oxidation to oxides of sulfur. Because these processes rely on oxidation, gas constituents that cannot be oxidized under the process conditions will not be removed. The main product of sulfur oxidation to oxides of sulfur is sulfur dioxide. Iron Sponge ProcessThe iron sponge process is the oldest and still the most widely used batch process for sweetening of natural gas and natural gas liquids. The process was implemented during the 19th century. Large-scale, commercial operations have discontinued this process due to the high labor costs of removing packed beds. However, its simplicity, low capital costs, and relatively low media cost continue to make the process an ideal solution for hydrogen sulfide removal. The process is usually best applied to gases containing low to medium concentrations (300 ppm) of hydrogen sulfide or mercaptans.

This process tends to be highly selective and does not normally remove significant quantities of carbon dioxide. As a result, the hydrogen sulfide stream from the process is usually high purity. Use of the iron sponge process for sweetening sour gas is based on adsorption of the acid gases on the surface of the solid sweetening agent followed by chemical reaction of ferric oxide (Fe2O3) with hydrogen sulfide:2Fe2O3 + 6H2S 2Fe2S3 + 6H2O (equation 1)

The reaction requires the presence of slightly alkaline water and a temperature below 43C (110 F) and bed alkalinity should be checked regularly, usually on a daily basis. A pH level on the order of 810 should be maintained through the injection of caustic soda with the water. If the gas does not contain sufficient water vapor, water may need to be injected into the inlet gas stream.The ferric sulfide produced by the reaction of hydrogen sulfide with ferric oxide can be oxidized with air to produce sulfur and regenerate the ferric oxide:

2Fe2S3 + 3O2 2Fe2O3 + 6S (eq 2)S2 + 2O2 2SO2 (eq 3)

The regeneration step, i.e., the reaction with oxygen, is exothermic and air must be introduced slowly so the heat of reaction can be dissipated. If air is introduced quickly, the heat of reaction may ignite the bed. Some of the elemental sulfur produced in the regeneration step remains in the bed. After several cycles this sulfur will cake over the ferric oxide, decreasing the reactivity of the bed. Typically, after 10 cycles the bed must be removed and a new bed introduced into the vessel. In some designs the iron sponge may be operated with continuous regeneration by injecting a small amount of air into the sour gas feed. The air regenerates ferric sulfide while hydrogen sulfide is removed by ferric oxide.

In the process as shown in Figure, the sour gas should pass down through the bed. In the case where continuous regeneration is to be utilized, a small concentration of air is added to the sour gas before it is processed. This air serves to regenerate the iron oxide continuously, which has reacted with hydrogen sulfide, which serves to extend the onstream life of a given tower but probably serves to decrease the total amount of sulfur that a given weight of bed will remove. The number of vessels containing iron oxide can vary from one to four. In a two-vessel process, one of the vessels would be onstream removing hydrogen sulfide from the sour gas while the second vessel would either be in the regeneration cycle or having the iron sponge bed replaced.

When periodic regeneration is used, a tower is operated until the bed is saturated with sulfur and hydrogen sulfide begins to appear in the sweetened gas stream. At this point the vessel is removed from service and air is circulated through the bed to regenerate the iron oxide. Regardless of the type of regeneration process used, a given iron oxide bed will lose activity gradually and eventually will be replaced. For this reason the vessels in Figure 7-1 should be designed to minimize difficulties in replacing the iron sponge in the beds. The change out of the beds is hazardous. Exposure to air when dumping a bed can cause a sharp rise in temperature, which can result in spontaneous combustion of the bed. Care must be exercised in opening the tower to the air. The entir bed should be wetted before beginning the change out operation.Zinc oxide process Zinc oxide is also used for hydrogen sulfide removal from the gas stream. The zinc oxide media particles are extruded cylinders 34 mm in diameter and 48 mm in length. This uniform sizing allows for relatively accurate pressure drop calculations in designing reactors. The general reaction of zinc oxide with hydrogen sulfide is: ZnO + H2S ZnS + H2OAt increased temperatures (400 to 700F), zinc oxide has a rapid reaction rate, therefore providing a short mass transfer zone, resulting in a short length of unused bed and improved efficiency.The ferrox process is based on the same chemistry as the iron oxide process except that it is fluid and continuous.The Stretford process employs a solution containing vanadium salts and anthraquinone disulfonic acid.Slurry processes were developed as alternatives to iron sponge. Slurries of iron oxide have been used to selectively absorb hydrogen sulfide. The disadvantages include foaming and high corrosion rates. However, this has been circumvented by coating the contact vessels with phenolic or epoxy resins. The chemical cost for these processes is higher than that for iron sponge process, but this is partially offset by the ease and lower cost with which the contact tower can be cleaned out and recharged.

Slurry processesChemsweet process The Chemsweet process is a batch process for the removal of hydrogen sulfide from natural gas. Chemicals used are a mixture of zinc oxide, zinc acetate, water, and a dispersant to keep the zinc oxide particles in suspension. When one part is mixed with five parts of water the acetate dissolves and provides a controlled source of zinc ions that react instantaneously with the bisulfide and sulfide ions that are formed when hydrogen sulfide dissolves in water. The zinc oxide replenishes the zinc acetate. The following reactions are performed in a Chemsweet process.Sweetening: ZnAc2 + H2S ZnS + 2HAc Regeneration: ZnO + 2HAc ZnAc2 + H2O Overall: ZnO + H2S ZnS + H2O The presence of carbon dioxide in the natural gas is of little consequence as the pH of the slurry is low enough to prevent significant absorption of carbon dioxide, even when the ratio of CO2 to H2S is high.The Chemsweet process can treat gas streams with a high hydrogen sulfide concentration and has been operated between pressures of 89 and 1415 psia. Mercaptan concentrations in excess of 10% of the hydrogen sulfide concentration in the gas stream can be a problem. Some of the mercaptans will react with the zinc oxide and be removed from the gas. The resulting zinc mercaptides [Zn(OH)RH] will form a sludge and possibly cause foaming problems.Sulfa-Check Process: The Sulfa-Check process selectively removes hydrogen sulfide and mercaptans from natural gas in the presence of carbon dioxide. The process uses sodium nitrite (NaNO2). Gas streams with elevated oxygen levels with the Sulfa-Check process will produce some nitrogen oxides in the gas stream. Removal of hydrogen sulfide is not affected under short contact times, as the reaction is almost instantaneously. Sodium hydroxide and sodium nitrite are consumables in the processes and cannot be regenerated. The process uses an aqueous solution of sodium nitrite buffered to stabilize the pH above 8.The claimed reaction with hydrogen sulfide forms elemental sulfur, ammonia, and caustic soda as follows:NaNO2 + 3H2S NaOH + NH3 + 3S + H2O Other reactions forming the oxides of nitrogen do occur and carbon dioxide in the gas reacts with the sodium hydroxide to form sodium carbonate and sodium bicarbonate. The spent solution is a slurry of fine sulfur particles in a solution of sodium and ammonium salts.Amine ProcessesChemical absorption processes with aqueous alkanolamine solutions are used for treating gas streams containing hydrogen sulfide and carbon dioxide. However, depending on the composition and operating conditions of the feed gas, different amines can be selected to meet the product gas specification.Amines are categorized as being primary, secondary, and tertiary depending on the degree of substitution of the central nitrogen by organic groups.Primary amines react directly with H2S, CO2, and carbonyl sulfide (COS). Examples of primary amines include monoethanolamine (MEA) and the proprietary diglycolamine agent (DGA).Secondry amines react directly with H2S and CO2 and react directly with some COS. The most common secondry amine is diethanolamine (DEA), while diisopropanolamine (DIPA) is another example of a secondary amine, which is not as common anymore in amine-treating systems.

Tertiary amines react directly with H2S, react indirectly with CO2, and react indirectly with little COS. The most common examples of tertiary amines are methyldiethanolamine (MDEA) and activated methyldiethanolamine.Processes using ethanolamine and potassium phosphate are now widely used. The ethanolamine process, known as the Girbotol process, removes acid gases (hydrogen sulfide and carbon dioxide) from liquid hydrocarbons as well as from natural and from refinery gases.

The Girbotol treatment solution is an aqueous solution of ethanolamine, which is an organic alkali that has the reversible property of reacting with hydrogen sulfide under cool conditions and releasing hydrogen sulfide at high temperatures. The ethanolamine solution fills a tower called an absorber through which the sour gas is bubbled.Purified gas leaves the top of the tower, and the ethanolamine solution leaves the bottom of the tower with the absorbed acid gases. The ethanolamine solution enters a reactivator tower where heat drives the acid gases from the solution. Ethanolamine solution, restored to its original condition, leaves the bottom of the reactivator tower to go to the top of the absorber tower, and acid gases are released from the top of the reactivator.MEA is a stable compound and, in the absence of other chemicals, suffers no degradation or decomposition at temperatures up to its normal boiling point. MEA reacts with H2S and CO2 as follow:2(RNH2) + H2S (RNH)2S 2(RNH2) + CO2 RNHCOONH3R These reactions are reversible by changing the system temperature. MEA also reacts with carbonyl COS and carbon disulfide (CS2) to form heatstable salts that cannot be regenerated.DEA is a weaker base than MEA and therefore the DEA system does not typically suffer the same corrosion problems but does react with hydrogen sulfide and carbon dioxide:2R2NH + H2S (R2NH)2S 2R2NH + CO2 R2NCOONH2R2Selecting criteria of amines for sweetening processesProcess DescriptionThe general process flow diagram for an amine-sweetening plant varies little, regardless of the aqueous amine solution used as the sweetening agent. The sour gas containing H2S and/or CO2 will nearly always enter the plant through an inlet separator (scrubber) to remove any free liquids and/or entrained solids. The sour gas then enters the bottom of the absorber column and flows upward through the absorber in intimate countercurrent contact with the aqueous amine solution, where the amine absorbs acid gas constituents from the gas stream. Sweetened gas leaving the top of the absorber passes through an outlet separator and then flows to a dehydration unit (and compression unit, if necessary) before being considered ready for sale.In many units the rich amine solution is sent from the bottom of the absorber to a flash tank to recover hydrocarbons that may have dissolved or condensed in the amine solution in the absorber. The rich solvent is then preheated before entering the top of the stripper column. The amineamine heat exchanger serves as a heat conservation device and lowers total heat requirements for the process. A part of the absorbed acid gases will be flashed from the heated rich solution on the top tray of the stripper. The remainder of the rich solution flows downward through the stripper in countercurrent contact with vapor generated in the reboiler. The reboiler vapor (primarily steam) strips the acid gases from the rich solution.The acid gases and the steam leave the top of the stripper and pass overhead through a condenser, where the major portion of the steam is condensed and cooled. The acid gases are separated in the separator and sent to the flare or to processing. The condensed steam is returned to the top of the stripper as reflux. The lean amine solution from the bottom of the stripper column is pumped through an amineamine heat exchanger and then through a cooler before being introduced to the top of the absorber column. The amine cooler serves to lower the lean amine temperature to the 100F range. Higher temperatures of the lean amine solution will result in excessive amine losses through vaporization and also lower acid gas-carrying capacity in the solution because of temperature effects.Experience has shown that amine gas treatment is a fouling service. Particulates formed in the plant as well as those transported into the plant can be very bothersome. A filtration scheme of mechanical and activated carbon filters is therefore important in maintaining good solution control.

Mechanical filters such as cartridge filters or precoat filters remove particulate material while carbon filters remove chemical contaminants such as entrained hydrocarbons and surface-active compounds.

Sulphur recovery processes:

The side stream from acid gas treating units consists mainly of hydrogen sulfide/or carbon dioxide. Carbon dioxide is usually vented to the atmosphere. Hydrogen sulfide could be routed to an incinerator or flare, which would convert the H2S to SO2 . The release of H2S to the atmosphere may be limited by environmental regulations. There are many specific restrictions on these limits. In any case, environmental regulations severely restrict the amount of H2S that can be vented or flared in the regeneration cycle.Most sulfur recovery processes use chemical reactions to oxidize H2S and produce elemental sulfur. These processes are generally based either on the reaction of H2S and O2 or H2S and SO2. Both reactions yield water and elemental sulfur. These processes involve specialized catalysts and/or solvents. These processes can be used directly on the produced gas stream. Where large flow rates are encountered, it is more common to contact the produced gas stream with a chemical or physical solvent and use a direct conversion process on the acid gas liberated in the regeneration step.There are two common methods of sulfur recovery: liquid redox and Claus sulfur recovery processes.Liquid redox sulfur recovery processes are liquid-phase oxidation processes that use a dilute aqueous solution of iron or vanadium to remove H2S selectively by chemical absorption from sour gas streams. These processes can be used on relatively small or dilute H2S stream to recover sulfur from the acid gas stream. The mildly alkaline lean liquid scrubs the H2S from the inlet gas stream, and the catalyst oxidizes the H2S to elemental sulfur. The reduced catalyst is regenerated by contact with air in the oxidizer(s). Sulfur is removed from the solution by flotation or settling, depending on the process.The Claus sulfur recovery process is the most widely used technology for recovering elemental sulfur from sour gas. The Claus process is used to recover sulfur from the amine regenerator vent gas stream in plants where large quantities of sulfur are present. However, this process is used to treat gas streams with a maximum H2S content of 15%. The chemistry of the units involves partial oxidation of hydrogen sulfide to sulfur dioxide and the catalytically promoted reaction of H2S and SO2 to produce elemental sulfur. The reactions are staged and are as follows.H2S + 3/2 O2 SO2 + H2O; thermal stage SO2 + 2H2S 3S+ 2H2 O; thermal and catalytic stage Natural Gas Dehydration Natural gas usually contains water, in liquid and/or vapor form, at source and/or as a result of sweetening with an aqueous solution. It is necessary to reduce and control the water content of gas to ensure safe processing and transmission. The major reasons for removing the water from natural gas are as follow: Natural gas can combine with liquid or free water to form solid hydrates that can plug valves fittings or even pipelines. Water can condense in the pipeline, causing slug flow and possible erosion and corrosion.Water vapor increases the volume and decreases the heating value of the gas.

Condensate removal

Composition of natural gas condensateGas condensate has a specific gravity ranging from 0. 5 to 0.8 and it may contain :Hydrogen sulfide (H2S}Thiols traditionally also called mercaptansCarbon dioxide (CO2)Straight-chain alkanes having from 2 to 12 carbon atoms (denoted as C2 to C12)Cyclohexane and perhaps other naphthenesAromatics (benzene, toluene, xylenes and ethylbenzene)

Commonly used aminesThere are many different amines used in gas treating:Monoethanolamine (MEA)

Diethanolamine (DEA)

Methyldiethanolamine (MDEA)

Diisopropylamine (DIPA)

Aminoethoxyethanol (diglycolamine) (DGA)